Method and system of heating a fluid catalytic cracking unit having a regenerator and a reactor

ABSTRACT

In at least one embodiment of the present invention, a method of heating a FCC unit having a regenerator and a reactor having overall CO 2  reduction is provided. The method comprises compressing syngas to define compressed syngas. Separating a first stream of gas comprising CO 2  from the compressed syngas. A second stream of gas comprising O 2  is expanded with the first stream of gas to produce a feed gas. The feed gas is introduced to the regenerator at gasification conditions to burn coke from coke heavy spent catalyst advanced from the reactor, producing syngas and heat for operating the reactor at reaction temperatures.

THE NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT

This application is the result of a joint research agreement between UOPLLC and BP Products North America Inc.

BACKGROUND OF THE INVENTION

The present invention relates to methods and systems of reducing carbondioxide emissions in a fluid catalytic cracking unit.

The fluidized catalytic cracking of hydrocarbons is the mainstay processfor the production of gasoline and light hydrocarbon products from heavyhydrocarbon charge stocks such as vacuum gas oils (VGO) or residualfeeds. Large hydrocarbon molecules associated with the heavy hydrocarbonfeed are cracked to break the large hydrocarbon chains thereby producinglighter hydrocarbons. These lighter hydrocarbons are recovered asproduct and can be used directly or further processed to raise theoctane barrel yield relative to the heavy hydrocarbon feed.

The basic equipment or apparatus for the fluidized catalytic cracking(FCC) of hydrocarbons has been in existence since the early 1940's. Thebasic components of the FCC process include a reactor, a regenerator,and a catalyst stripper. The reactor includes a contact zone where thehydrocarbon feed is contacted with a particulate catalyst and aseparation zone where product vapors from the cracking reaction areseparated from the catalyst. Further product separation takes place in acatalyst stripper that receives catalyst from the separation zone andremoves entrained hydrocarbons from the catalyst by counter-currentcontact with steam or another stripping medium.

The FCC process is carried out by contacting the startingmaterial—generally VGO, reduced crude, or another source of relativelyhigh boiling hydrocarbons—with a catalyst made up of a finely divided orparticulate solid material. The catalyst is transported like a fluid bypassing gas or vapor through it at sufficient velocity to produce adesired regime of fluid transport. Contact of the oil with the fluidizedmaterial catalyzes the cracking reaction. The cracking reaction depositscoke on the catalyst. Coke is comprised of hydrogen and carbon and caninclude other materials in trace quantities such as sulfur and metalsthat enter the process with the starting material. Coke interferes withthe catalytic activity of the catalyst by blocking active sites on thecatalyst surface where the cracking reactions take place. Catalyst istraditionally transferred from the stripper to a regenerator forpurposes of removing the coke by oxidation with an oxygen-containinggas. An inventory of catalyst having a reduced coke content relative tothe catalyst in the stripper, hereinafter referred to as regeneratedcatalyst, is collected for return to the reaction zone. Oxidizing thecoke from the catalyst surface releases a large amount of heat, aportion of which escapes the regenerator with gaseous products of cokeoxidation generally referred to as flue gas. The balance of the heatleaves the regenerator with the regenerated catalyst. The fluidizedcatalyst is continuously circulated from the reaction zone to theregeneration zone and then again to the reaction zone. The fluidizedcatalyst, as well as providing a catalytic function, acts as a vehiclefor the transfer of heat from zone to zone. Catalyst exiting thereaction zone is spoken of as being spent, i.e., partially deactivatedby the deposition of coke upon the catalyst. Specific details of thevarious contact zones, regeneration zones, and stripping zones alongwith arrangements for conveying the catalyst between the various zonesare well known to those skilled in the art.

Refining companies are under increased pressure to reduce CO₂ emissionsas a result of carbon tax legislation and other drivers such as a desireto demonstrate long-term sustainability. Thus, there is a need toprovide a way to reduce the carbon dioxide emissions of a fluidcatalytic cracking unit.

One solution to reducing carbon dioxide emissions involves operating theFCC regenerator at gasification conditions and supplying the regeneratorwith a feed comprising recycled carbon dioxide and oxygen. In thisscenario, carbon dioxide is reduced in part because the carbon dioxideis being recycled from a synthesis gas separator unit. One issue withthis solution, however, is that under gasification conditions, theregenerator may not supply enough heat to the FCC reactor for crackingthe hydrocarbon feedstock with the catalyst.

BRIEF SUMMARY OF THE INVENTION

Embodiments of the present invention generally provide methods andsystems of heating a fluid catalytic cracking unit having a reactor anda regenerator operating at gasification conditions for overall carbondioxide reduction. The methods and systems of the present inventionprovide solutions to generating sufficient heat for operating thereactor at reaction temperature.

In at least one embodiment, a method of heating a fluid catalyticcracking unit having a regenerator and a reactor for overall carbondioxide reduction is provided. The method comprises compressing syngasat an inlet pressure to a predetermined high pressure to definecompressed syngas. The syngas comprises carbon dioxide (CO₂), carbonmonoxide (CO), water (H₂O), hydrogen sulfide (H₂S) and carbonyl sulfide(COS). A first stream of gas comprising CO₂ is separated from thecompressed syngas. The first stream of gas is expanded with a secondstream of gas comprising oxygen (O₂) to a predetermined low pressure todefine a feed gas. The feed gas is introduced to the regenerator atgasification conditions to burn coke from coke heavy spent catalystadvanced from the reactor. Burning of the coke produces the syngas andheat for operating the reactor at reaction temperatures.

In one aspect of the present invention, the method further comprisesproviding a turbo-expander train including a first compressor, anexpander, and a shaft operatively coupled to both the first compressorand the expander such that the expander rotates the shaft which drivesthe first compressor. The syngas is compressed by the first compressorto define the compressed syngas. The expander expands the first streamof gas with the second stream of gas to produce the feed gas and toextract energy from the first and second streams of gas to drive theexpander to rotate the shaft.

In at least one other embodiment of the present invention, a system forheating a fluid catalytic cracking unit having a regenerator and areactor for overall reduction of carbon dioxide reduction is provided.The system comprises a compressor for compressing syngas at an inletpressure to a predetermined high pressure to define compressed syngas.The syngas comprises CO₂, CO, H₂O, H₂S and COS. In fluid communicationwith the compressor is a separator unit. The separator unit isconfigured to separate a first stream of gas comprising CO₂ from thecompressed syngas. An expander is in fluid communication with theseparator unit. The expander is configured for expanding the firststream of gas with a second stream of gas comprising O₂ to define a feedgas. At gasification conditions is the regenerator for regenerating cokeheavy spent catalyst from the reactor. The regenerator is configured forreceiving the feed gas to burn coke from the coke heavy spent catalyst,producing the syngas and heat for operating the reactor at reactiontemperatures.

Further objects, features and advantages of the invention will becomeapparent from consideration from the following description and theappended claims when taken in connection with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 a is a schematic diagram of a fluid catalytic cracking unit;

FIG. 1 b is a schematic diagram of a reactor and a regenerator of thefluid catalytic cracking unit of FIG. 1 a;

FIG. 1 c is a schematic diagram of a fluid catalytic cracking unit inaccordance with at least one embodiment of the present invention;

FIG. 1 d is a schematic diagram of a fluid catalytic cracking unit inaccordance with at least another embodiment of the present invention;and

FIG. 2 is a flow chart of an example of a method of heating a fluidcatalytic cracking in accordance with the present invention.

DETAILED DESCRIPTION OF THE INVENTION

Detailed embodiments of the present invention are disclosed herein. Itis understood however, that the disclosed embodiments are merelyexemplary of the invention that may be embodied in various andalternative forms. The figures are not necessarily to scale; somefigures may be configured to show the details of a particular component.Therefore, specific structural and functional details disclosed hereinare not interpreted as limiting but merely as a representative basiswith the claims and for teaching one skilled in the art to practice thepresent invention.

Examples of the present invention seek to overcome some of the concernsassociated with heating a fluid catalytic cracking unit while reducingoverall CO₂ emissions from the refinery. A conventional fluid catalyticcracking unit burns coke from the spent catalyst by feeding gascomprising air and/or O₂ into the regenerator, producing flue gas, whichcontains CO₂ but is typically rich in nitrogen (N₂). However, byintroducing a feed gas comprising O₂ with CO₂ and/or H₂O into theregenerator, a synthesis gas (syngas) may be produced. Specifically, theCO₂ and the O₂ in the feed gas may react with the carbon-hydrogen basedcoke to produce CO₂, CO, H₂O and H₂ by a “dry” gasification process andthe H₂O and the O₂ in the feed gas may react with the coke to produceCO₂, CO and H₂ by a “wet” gasification process.

The H₂ in the syngas may be used as a raw material source for otheroperations within the refinery which may reduce the need for anadditional fuel source, such as a hydrogen furnace. Additionally, theCO₂ in the syngas may be more easily sequestered than CO₂ in N₂ richflue gas, such as for example, by limestone structures or any othersuitable means known to those skilled in the art. By reducing oreliminating the need for a hydrogen furnace and by sequestering the CO₂for recycling as a feed gas for operating the regenerator atgasification conditions, overall CO₂ emission may be reduced from therefinery.

However, burning coke on spent catalyst under gasification conditions isnot as exothermic a process as burning coke in air and/or O₂. Moreover,the coke fuel is typically limited because only about 4%, for example,of a VGO feedstock fed to the reactor is converted to coke which isdeposited upon the catalyst. Accordingly, less heat is generated undergasification conditions and since the heat generated in the regeneratoris recovered by the reactor for the cracking reaction, the reactor maybe at a lower temperature which could adversely affect cracking of thehydrocarbon feedstock. Applicant has discovered that by introducing ahigh Conradson carbon feedstock into the reactor, a “coke heavy” spentcatalyst may be generated which provides more fuel to the regeneratorand thus, more heat is produced to support the operation of the reactorat reaction temperatures. In one example, a vacuum residue feedstock isfed into the reactor producing the coke heavy spent catalyst. In analternative example, a solvent deasphalter pitch (SDA pitch) is fed intothe reactor to produce the coke heavy spent catalyst. Vacuum residue isdefined herein as a low value hydrocarbon fraction of crude which isrich in asphaltenes and heavy Conradson carbon e.g. 18 to 30 or more.SDA pitch is defined herein as being that portion of the vacuum residuethat is insoluble in a paraffinic solvent. SDA pitch contains themajority of the vacuum residue's asphaltenes and Conradson carbon and istherefore very rich in carbon. Coke heavy spent catalyst is definedherein as being catalyst having at least about 12 percent by weight ofthe crude that is fed to the reactor being converted to coke which isdeposited onto the catalyst. When the coke heavy spent catalyst isregenerated in the regenerator, the significantly higher coke contentprovides additional fuel. The additional fuel/coke generates more heatwhen it is burned and thus, allows the reactor to operate at reactiontemperatures for cracking the feedstock.

Referring now to the drawings, FIG. 1 a illustrates a fluid catalyticcracking (FCC) unit and separation system 10. As shown, the FCC unit 10comprises a reactor 12 that is configured to receive crude or ahydrocarbon feedstock 30 (fresh feed) and a regenerator 14 in fluidcommunication with the reactor 12 to receive spent catalyst. The reactor12 cracks the feedstock 30 therein to an effluent containinghydrocarbons ranging from methane through relatively high boiling pointmaterials along with H₂ and H₂S. During the cracking reaction, acarbonaceous by-product is deposited on the circulating catalyst. Thismaterial, termed “coke,” is continuously burned off the spent catalystin the regenerator 14 as will be mentioned below.

The FCC unit 10 comprises the regenerator 14 for regenerating spentcatalyst from the reactor 12. The regenerator 14 is configured toreceive a feed gas 22 from an outside source and spent catalyst from thereactor 12. From the reactor 12, the spent catalyst has coke depositedthereon, reducing the activity of the catalyst. The regenerator 14receives the feed gas 22 to burn the coke off the spent catalyst,thereby producing a flue gas 26 that exits a flue gas line 28 to aflue-gas system. The flue gas 26 may comprise CO, CO₂, H₂O (steam),SO_(x) and N₂, but it is typically very rich in N₂ The regenerator 14 isconfigured to rejuvenate or reactivate the spent catalyst by burning thedeposited coke off the spent catalyst with the feed gas 22.

The regenerator 14 reactivates the catalyst so that, when returned tothe reactor 12, the catalyst is in optimum condition to perform itscracking function. The regenerator 14 serves to gasify the coke from thecatalyst particles and, at the same time, to impart sensible heat to thecirculating catalyst. The energy carried by the hot regenerator catalystis used to satisfy the thermal requirements for the reactor 12 of theFCC unit 10.

It is to be noted that the FCC unit 10 may have a number of optionalunits associated with the flue-gas system. In one embodiment, the fluegas 26 may comprise catalyst fines, N₂ from air used for combustion,products of coke combustions (e.g., oxides of carbon, sulfur, nitrogen,and water vapor), and trace quantities of other compounds. The flue gas26 exits the regenerator 14 at a temperature of approximately 1325degrees Fahrenheit (F), but may be as high as 1400 degrees F. or as lowas 1200 degrees F., and at pressures of between about 20 and 50 poundsper square inch gauge (psig). The thermal and kinetic energy of the fluegas 26 can be converted to steam or used to drive a turbo-expandergenerator system for electrical power generation. Unconverted CO in theflue gas 26 can be combusted to CO₂ in a CO boiler with production ofhigh-pressure steam. Catalyst fines may be removed by a solid removalunit, such as for example, an electrostatic precipitator. CO₂ from theregenerator and/or CO boiler is released to the atmosphere.

Referring now to FIGS. 1 a to 1 b, from the regenerator 14, hotregenerated catalyst is fed back to the reactor 12 via reactivatedcatalyst return line 20 and vaporizes the hydrocarbon feedstock 30 todefine resultant vapors. The resultant vapors carry the catalyst upwardthrough a riser 16 of the reactor 12 with a minimum of back mixing. Atthe top of the riser 16, desired cracking reactions have been completedand the catalyst is quickly separated from the hydrocarbon vapors tominimize secondary reactions. The catalyst-hydrocarbon mixture from theriser 16 is discharged into the reactor 12 vessel through a separationdevice 18, e.g., a riser termination device, achieving a substantialdegree of catalyst-gas separation, e.g., at least 90 weight percentproduct vapor separation from catalyst. A final separation of catalystand product vapor may be accomplished by cyclone separation.

The reactor effluent is directed to a main fractionator or fractionationcolumn 50 of the unit 10 for resolution into gaseous light olefinco-products, FCC gasoline, and cycle stocks. The spent catalyst dropsfrom within the reactor 12 vessel into a stripping section 24 thereof,where a countercurrent flow of steam removes interstitial and someadsorbed hydrocarbon vapors, defining stripped spent catalyst. Strippedspent catalyst descends through a first standpipe 23 and into theregenerator 14.

To maintain the activity of the working-catalyst inventory at a desiredlevel and to make-up for any catalyst lost from the system with the fluegas 26, fresh catalyst may be introduced into the circulating-catalystsystem by any suitable manner. For example, this may be accomplished byway of a catalyst storage hopper (not shown). Moreover, an additionalstorage hopper (not shown) may be used to hold spent catalyst withdrawnfrom the circulating system as necessary to maintain the desired workingactivity and to hold all catalyst inventory when the FCC unit 10 is shutdown for maintenance and repairs.

As shown in FIGS. 1 a and 1 b, in the operation of the FCC unit 10,fresh feedstock 30 and (depending on product-distribution objectives)recycled cycle oils are introduced into the bottom of the riser 16together with a controlled amount of regenerated catalyst. The chargemay be preheated, either by heat exchange or, for some applications, bymeans of a fired heater.

Feedstocks 30 for the FCC process include mixtures of hydrocarbons ofvarious types, including relatively small molecules such as found ingasoline to large molecules of 60 or more carbon atoms. The feedstock 30may include a relatively small content of contaminant materials such asorganic sulfur, nitrogen compounds, and organometallic compounds. It isto be noted that the relative proportions of all such materials willvary with the geographic origin of the crude and the particular boilingrange of the FCC feedstock 30. However, the feedstocks 30 may be rankedin terms of their “crackabilities,” or the ease with which they can beconverted in an FCC unit. Crackability may be defined by a function ofthe relative proportions of paraffinic, naphthenic, and aromatic speciesin the feed.

The FCC unit 10 further includes a main-fractionation column 50 throughwhich the reactor effluent is separated into various products. Themain-fractionation comprises an overhead line 52, a first side cut line54, a second side line 56, a third side cut line 58, and a bottom line60. As shown, the overhead line 52 includes gasoline and lightermaterial, the first side cut line 54 includes naphtha, the second sidecut line 56 includes light cycle oil, the third side cut line 58includes heavy cycle oil, and the bottom line 60 includes slurry oil.The lines may include other products without falling beyond the scope orspirit of the present invention.

Reactor-product vapors are directed to the main fractionator 50 at whichgasoline and gaseous olefin-rich co-products are taken overhead androuted to a gas-concentration unit 70. At the main-fractionator 50,light-cycle oil is recovered as a side cut with the net yield of thismaterial being stripped for removal of light ends and sent to storage.Net column bottoms are yielded as slurry or clarified oil. Because ofthe high efficiency of the catalyst-hydrocarbon separation systemutilized in the reactor design, catalyst carry-over to the fractionator50 is minimized and it is not necessary to clarify the net heavy productyielded from the bottom of the fractionator 50 unless the material is tobe used in some specific application requiring low solids content suchas the production of carbon black. In some instances, heavy material canbe recycled to the reactor riser 16.

Maximum usage is made of the heat available at the main column 50.Typically, light-cycle and heavy-cycle oils are utilized in thegas-concentration section 70 for heat-exchange purposes, and steam isgenerated by circulating main-column bottoms stream.

The gas-concentration column 70 is in fluid communication with overheadline of the main-fractionation column 50. From the overhead line 52, thegas-concentration column 50 receives unstable gasoline and lighterproducts that are separated therethrough into fuel gas for alkylation,polymerization, and debutanized gasoline.

The gas-concentration section 70 may be one or an assembly of absorbersand fractionators that separate the main-column overhead into gasolineand other desired light products. Olefinic gases from other processessuch as coking may be also sent to the FCC gas-concentration section.The gas-concentration unit may have one or a plurality of columns. Forexample, the gas-concentration unit may be a “four-column”gas-concentration plant comprising a primary absorber, a secondaryabsorber, a stripper, and a debutanizer.

Referring now to FIG. 1 c, at least one embodiment of a system 80 forheating a fluid catalytic cracking unit that has a regenerator 14 and areactor 12 for overall carbon dioxide reduction is provided. The system80 comprises a compressor 82 for compressing syngas 84 at an inletpressure to a predetermined high pressure to define a compressed syngas85. The syngas 84 is comprised of CO₂, CO, H₂O and COS and may furtherinclude H₂ and H₂S. In one example, the compressor 82 has a compressionratio between about 5:1 and 10:1 and preferably has a compression ratioof about 7:1. The inlet pressure may be, for example, between about 25and 35 psig. The compressor 82 preferably compresses the syngas 84 to apressure between about 150 and 500 psig.

A separator unit 86 is in fluid communication with the compressor 82.The separator unit 86 is configured to separate at least CO₂ from thecompressed syngas 85 to produce a first stream of gas 88 comprising CO₂.In one example, the separator unit uses a wet gas scrubbing process suchas amine absorption, Rectisol™, or Selexol™, which is used to removeand/or separate H₂S, COS, and CO₂ from the compressed syngas 85 toproduce the first stream of gas 88. Other suitable forms of separatingknown to those skilled in the art may also be used. The syngas gas 85may also contain CO and H₂, which can be mixed with steam and sent to awater-gas shift reactor to convert CO to CO₂, thus producing additionalH₂. The H₂ may be further separated from the CO₂ via a process known aspressure swing adsorption. In this scenario, the separated H₂ 72 mayminimize the need to burn hydrocarbon fuels elsewhere in the plant foruse by another system, thereby reducing overall CO₂ emissions from therefinery. For example, the separated H₂ 72 may be used by another systemby being burned as a fuel or used to hydro-treat or hydrocrack otherhydrocarbons.

Heat recovery and cooling by a cooling unit 90 may be performedsubsequent to compressing the syngas 84 by the compressor 82 but priorto the compressed syngas 85 being processed by the separation unit 86.In one example, the cooling unit 90 cools the compressed syngas 85having a temperature between about 600 and 800 degrees F. to betweenabout 300 and 500 degrees F.

In one embodiment, the first stream of gas 88, which may contain aportion of the separated CO plus H₂ that is in excess of the amountrequired for refinery H₂ production, is supplied to an expander 100which is in fluid communication with the separator unit 86. A secondstream of gas 96 comprising O₂ may also be supplied to the expander 100.Alternatively and as illustrated in FIG. 1 c, the first stream of gas 88may initially be supplied to a combustion zone 92 or combustor with thesecond stream of gas 96. In this scenario, the combustion zone 92 is indirect fluid communication with the separator unit 86. In still yetanother example and as illustrated in FIG. 1 d, the first stream of gas88 may be supplied initially to a second compressor 94 which is in fluidcommunication with both the separator unit 86 and the combustion zone92. The second compressor 94 further compresses the first stream of gas88 prior to the combustion zone 92 receiving the gas 88.

The combustion zone 92 is configured for combusting the second stream ofgas 96 comprising O₂ with the first stream of gas 88 to a predeterminedhigh temperature to produce heated gas 98. If the first stream of gas 88contains any H₂ and/or CO, preferably the first and second streams ofgas are combusted in the combustion zone 92 prior to being received bythe expander 100. In one example, the predetermined high temperature isbetween about 1800 and 2100 degrees F. The combustion zone combusts anyH₂ and/or CO from the first stream of gas 88 with the O₂ from the secondstream of gas 96 to produce the heated gas 98 comprising CO₂ and/or H₂O.Moreover, some of the O₂ from the second stream of gas 96 willpreferably remain un-reacted, especially if the second stream of gas isstoichiometrically in excess to the first stream of gas 88. In thisscenario, the excess O₂ forms a portion of the heated gas 98.

The expander 100 may be in direct fluid communication with the separatorunit 86. Alternatively, the expander 100 may be in direct fluidcommunication with the combustion zone 92 and be in indirect fluidcommunication with the separator unit 86. The expander 100 is configuredfor expanding the first and second streams of gas 88 and 96 to apredetermined low pressure to define a feed gas 102. If the first andsecond streams of gas 88 and 96 are initially directed to the combustionzone 92, then the expander 100 expands these streams of gas 88 and 96 inthe form of the heated gas 98. In one embodiment, the expander 100 is a10 to 15 stage turbo-expander. The feed gas 102 has a pressure betweenabout 30 and 70 psig and preferably between about 30 and 40 psig and mayhave a temperature between about 1200 and 1600 degrees F. when thecombustion zone 92 is used. Alternatively, if the first and secondstreams of gas 88 and 96 are not combusted, the feed gas 102 may have atemperature of about 100 degrees F.

In at least one embodiment, the reactor 12 is configured for receiving alow value crude feed 104 rich in asphaltenes and Conradson carbon. Inone example, the low value crude feed 104 is substantially vacuumresidue. In another example, the low value crude feed 104 issubstantially SDA pitch.

The reactor 12 cracks the low value crude feed 104 with catalyst,producing coke heavy spent catalyst 106 which is advanced to theregenerator 14 via the first standpipe 23. Preferably at least about,with increasing preference in the order given, 12%, 14%, 16%, 18% and20% by weight of the low value crude feed 104 is converted to coke whichis deposited onto the catalyst to form the coke heavy spent catalyst106.

The regenerator 14 receives the feed gas 102, which in one examplecomprises O₂ and CO₂. The feed gas 102 may further include H₂O. Theregenerator 14 is operating at gasification conditions, burning cokefrom the coke heavy spent catalyst 106 with the feed gas 102. Theadditional coke deposited on the coke heavy spent catalyst 106 fuels theburning process and increases the combustion energy within theregenerator 14, enhancing the gasification process and producing syngasand heat. The syngas is preferably at a temperature between about 1200and 1850 degrees F. and may also be rich in CO and H₂.

Referring to FIGS. 1 c and 1 d, the compressor 82, the combustion zone92 and the expander 100 may be part of a turbo-expander train 110. Theturbo-expander train 110 includes a shaft 112 operably coupled to boththe expander 100 and the compressor 82 such that the expander 100rotates the shaft 112 which drives the compressor 82. The expander 100,acting as a turbine engine, extracts energy from the heated gas 98 byexpanding the heated gas 98. The expander 100 converts the extractedenergy to rotational energy which rotates the shaft 112. In anotherexample, the turbo-expander train 110 may further include a secondcompressor 94 which is operably coupled to the shaft 112 and is alsodriven by the expander 100.

The system 80 may include a solid removal unit 114 and a cooling unit116. The cooling unit 116 is in fluid communication with the solidremoval unit 114 and the compressor 82. The solid removal unit 114 is influid communication with the regenerator 14 and may be used to removecatalyst fines from the syngas 84 prior to the syngas 84 being receivedby the cooling unit 116 and/or the compressor 82. In one example, thecooling unit 116 cools the syngas 84 from a temperature between about1200 and 1850 degrees F., but preferably between about 1200 and 1400degrees F., to a temperature between about 300 and 600 degrees F.

In at least one other embodiment, the turbo-expander train 110 furtherincludes a motor generator 118. The motor generator 118 is operablycoupled to the shaft 112 and is driven by the expander 100. The motorgenerator 118 produces electrical power when the shaft 112 is rotated.The electrical power may be used for various processes within the plant.In one example, this electrical power minimizes the need to burn fuelelsewhere in the plant for power generation, thereby reducing overallCO₂ emissions from the refinery.

Referring to FIG. 2, at least one embodiment for a method of heating afluid catalytic cracking unit having a regenerator and a reactor foroverall carbon dioxide reduction is provided. The method comprisescompressing syngas 120 at an inlet pressure to a predetermined highpressure to define compressed syngas. In one example, the inlet pressureis between about 25 and 35 psig and the predetermined high pressure isbetween about 150 and 500 psig.

CO₂ is separated from the compressed syngas to provide a first stream ofgas 122 comprising CO₂. In one example, the first stream of gas iscombusted with a second stream of gas comprising O₂to produce heatedgas. The heated gas may have a temperature between about 1800 and 2100degrees F.

The first and second streams of gas may be expanded 126 to a lowpressure to define a feed gas. In the example where the first and secondstreams of gas are combusted, the expander expands the first and secondstreams of gas in the form of the heated gas.

The feed gas is introduced to the regenerator 128. The regenerator is atgasification conditions to burn coke from coke heavy spent catalyst,which was advanced from the reactor. Burning of the coke produces thesyngas and heat for operating the reactor at reaction temperatures. Inone example, the feed gas has a temperature between about 1200 and 1600degrees F. and the syngas produced within the regenerator has atemperature between 1200 and 1850 degrees F. and preferably betweenabout 1200 and 1400 degrees F.

In at least one other embodiment, the method further includes removingcatalyst fines and cooling the syngas to a temperature between 400 and600 degrees F. prior to the step of compressing. The compressed syngasmay also be cooled to a temperature between 300 and 500° F.

The following example (displayed in Tables 1 and 2) further illustratesembodiments of the invention. A comparison is made between: (1) a FCCunit with a reactor and a regenerator operating under combustionconditions (i.e. using air as the feed gas to the regenerator) and (2) aFCC unit with a reactor and a regenerator operating under gasificationconditions (i.e. using an artificially created feed gas comprising CO₂and O₂). Under normal FCC operations, the heat produced in theregenerator under combustion and gasification conditions (“total heatavailable”) is transferred to operate the reactor (“total heatrequired”).

In Table 1, this example calculates the total heat required by thereactor when a feedstock enters the riser at 450° F. and the reactorproduct exits at 980° F. The total heat available in the regenerator iscalculated with the regenerator operating at 1275° F. and circulating 7lbs of catalyst per pound of FCC feedstock. Assuming the coke has anapproximate formula of C₂₂H₁₁ and contains an indistinguishable amountof sulfur, the example requires 13.75 lbs of air (under combustionconditions) to burn each pound of coke. Based on these operatingconditions and assumptions, the reactor has a total heat requirement of620 Btu per lb of feedstock. The regenerator, under combustionconditions, has a total heat available of 13,332 Btu per lb of coke.Therefore, the minimum amount of coke on catalyst to supply the requiredheat to the reactor is 0.047 lb coke/lb feedstock [(620 Btu/lb offeedstock)/(13,332 Btu/lb of coke)] or about 4.7%.

TABLE 1 FCC Unit Operating Under Combustion Conditions ReactorRegenerator Source Btu/lb of feed Source Btu/lb of coke ΔH Feed 475 ΔHAir/Flue Gas −3,452 ΔH Reaction 132 ΔH Combustion 16,775 ΔH Steam 10Heat Loss −255 Heat Loss 3 Total Heat 13,332 Total Heat Required 620Available Coke = Total Heat Required/Total Heat Available = 620/13332 *100% = 4.7%

In Table 2, this example shifts from combustion conditions togasification conditions in the regenerator. If reactor conditions remainthe same as Table 1 (i.e. feedstock entering at 450° F. and productexiting at 980° F.), then the total heat required by the reactor willremain the same (620 Btu per lb of feedstock). Additionally, theregenerator will have to supply catalyst to the reactor at the same rateand temperature. Under gasification conditions, the total heat availablecan vary depending on the concentration of O₂ and CO₂ in the feed gas.In this example, assume the following reaction represents the heat ofcombustion based on one ratio of O₂ to CO₂ (C₂₂H₁₁+8½ O₂+5 CO₂→27CO+5½H₂). This reaction produces approximately 2,711 Btu per lb of coke.Assuming that the incoming feed gas must be heated from 100° F. to 1275°F., the heat requirement is approximately 571 Btu per lb of coke ((1.8lb gas per lb coke*0.27 Btu per lb ° F.*(1275° F.-100° F.)). Theregenerator, under gasification conditions, has a total heat availableof 1,885 Btu per lb of coke. In this example, the minimum amount of cokeon catalyst to supply the required heat to the reactor is 0.329 lbcoke/lb feedstock [(620 Btu/lb of feedstock)/(1,885 Btu/lb of coke)] orabout 32.9%. As discussed, this increased coke level is not typicallyachieved during normal operations of the FCC unit e.g. a VGO feedstockproduces only about 4% by weight of coke/feedstock. However, byintroducing a high Conradson carbon feedstock into the reactor a cokeheavy spent catalyst can be produced, which when burned within theregenerator may produce enough heat to satisfy the energy requirement ofthe reactor. In one example, the coke heavy spent catalyst burns toproduce at least about a 600 BTU/lb of the feedstock for operating thereactor at reaction temperatures.

TABLE 2 FCC Unit Operating Under Gasification Conditions ReactorRegenerator Source Btu/lb of feed Source Btu/lb of coke ΔH Feed 475 ΔHFeed Gas/Syngas −571 ΔH Reaction 132 ΔH Combustion 2,711 ΔH Steam 10Heat Loss −255 Heat Loss 3 Total Heat Available 1,885 Total Heat 620Required Coke = Total Heat Required/Total Heat Available = 620/1885 *100% = 32.9%

As a person skilled in the art will readily appreciate, the abovedescription is meant as an illustration of the implementation of theprinciples of this invention. This description is not intended to limitthe scope or application of the invention in that the invention issusceptible to modification, variation and change without departing fromthe spirit of this invention, as defined in the following claims.

1. A method of heating a fluid catalytic cracking unit having aregenerator and a reactor for overall carbon dioxide reduction, themethod comprising: compressing syngas comprising CO₂, CO, H₂O, H₂S andCOS at an inlet pressure to a predetermined high pressure to definecompressed syngas; separating a first stream of gas comprising CO₂ fromthe compressed syngas; expanding the first stream of gas with a secondstream of gas comprising O₂ to a predetermined low pressure to define afeed gas; and introducing the feed gas to the regenerator having cokeheavy spent catalyst from the reactor, the regenerator at gasificationconditions to burn coke from the coke heavy spent catalyst, producingthe syngas and heat for operating the reactor at reaction temperatures.2. The method according to claim 1 wherein the reactor is configured forreceiving feedstock that reacts with catalyst to produce the coke heavyspent catalyst and the heat for operating the reactor at reactiontemperatures is at least about 600 BTU per pound of the feedstock. 3.The method according to claim 2 wherein the feedstock comprises vacuumresidue and at least about 12 percent by weight of the vacuum residue isconverted to the coke which is deposited onto the catalyst to producethe coke heavy spent catalyst.
 4. The method according to claim 2wherein the feedstock comprises solvent deasphalter pitch and at leastabout 12 percent by weight of the solvent deasphalter pitch is convertedto the coke which is deposited onto the catalyst to produce the cokeheavy spent catalyst.
 5. The method according to claim 1 wherein thesyngas further comprises H₂ and the first stream of gas furthercomprises at least one of CO and H₂ and the method further comprisescombusting the first stream of gas with the second stream of gas to apredetermined high temperature to produce a heated gas, and the step ofexpanding includes expanding the heated gas to define the feed gas. 6.The method according to claim 5 wherein the predetermined hightemperature is between about 1800 and 2100 degrees Fahrenheit (F.). 7.The method according to claim 5 further comprising separating at least aportion of the H₂ from the compressed syngas, the portion of the H₂being used for another system, reducing overall CO₂ emissions.
 8. Themethod according to claim 1 wherein the predetermined high pressure isbetween about 150 and 500 psig.
 9. The method according to claim 1wherein the predetermined low pressure is between about 30 and 70 psig.10. The method according to claim 1 wherein the feed gas has atemperature between about 1200 and 1600 degrees Fahrenheit (F.).
 11. Themethod according to claim 1 wherein the syngas produced at the reactorhas a temperature between about 1200 and 1850 degrees Fahrenheit (F.).12. The method according to claim 1 wherein the feed gas comprises CO₂,O₂ and H₂O.
 13. The method according to claim 1 further comprisingremoving catalyst fines and cooling the syngas to a temperature betweenabout 300 and 600 degrees Fahrenheit (F.) prior to the step ofcompressing.
 14. The method according to claim 1 further comprisingcooling the compressed syngas to a temperature between about 300 and 500degrees Fahrenheit (F.).
 15. A method of heating a fluid catalyticcracking unit having a regenerator and a reactor for overall carbondioxide reduction, the method comprising: providing a turbo-expandertrain including a first compressor, an expander, and a shaft operativelycoupled to both the expander and the first compressor such that theexpander rotates the shaft which drives the first compressor;compressing syngas comprising CO₂, CO, H₂O, H₂S and COS at an inletpressure with the first compressor to a predetermined high pressure todefine compressed syngas; separating a first stream of gas comprisingCO₂ from the compressed syngas; expanding the first stream of gas with asecond stream of gas comprising O₂ by the expander to a predeterminedlow pressure, producing a feed gas and extracting energy from the firstand second streams of gas to drive the expander to rotate the shaft; andintroducing the feed gas to the regenerator having coke heavy spentcatalyst from the reactor, the regenerator at gasification conditions toburn coke from the coke heavy spent catalyst, producing the syngas andheat for operating the reactor at reaction temperatures.
 16. The methodaccording to claim 15 wherein the turbo-expander train further includesa combustion zone in fluid communication with the expander and the firststream of gas further comprises at least one of CO and H₂ and the methodfurther comprises combusting the first and second streams of gas by thecombustion zone to a predetermined high temperature to produce heatedgas, and the step of expanding includes expanding the heated gas,producing the feed gas and extracting energy from the heated gas by theexpander to drive the expander to rotate the shaft.
 17. The methodaccording to claim 16 wherein the turbo-expander train further includesa second compressor in fluid communication with the combustion zone andoperatively coupled to the shaft such that rotation of the shaft drivesthe second compressor, and the method further includes compressing thefirst stream of gas prior to the step of combusting.
 18. The methodaccording to claim 15 wherein the turbo-expander train further includesa motor generator operatively coupled to the shaft such that rotation ofthe shaft drives the motor generator, and the method further comprisesdriving the motor generator producing electrical energy.
 19. A systemfor heating a fluid catalytic cracking unit having a regenerator and areactor for overall carbon dioxide reduction, the system comprising: acompressor for compressing syngas comprising CO₂, CO, H₂O, H₂S and COSat an inlet pressure to a predetermined high pressure to definecompressed syngas; a separator unit in fluid communication with thecompressor and configured to separate a first stream of gas comprisingCO₂ from the compressed syngas; an expander in fluid communication withthe separator unit and configured for expanding the first stream of gaswith a second stream of gas comprising O₂ to a predetermined lowpressure to define a feed gas; and the regenerator at gasificationconditions for regenerating coke heavy spent catalyst from the reactorand configured for receiving the feed gas to burn coke from the cokeheavy spent catalyst, producing the syngas and heat for operating thereactor at reaction temperatures.
 20. The system according to claim 19wherein the compressor and the expander are part of a turbo-expandertrain, the turbo-expander train including a combustion zone in fluidcommunication with the separator unit and the expander, and a shaftoperatively coupled to both the expander and the compressor such thatthe expander rotates the shaft which drives the first compressor, thecombustion zone configured for combusting the first and second streamsof gas to a predetermined high temperature to produce heated gas, andthe expander configured for extracting energy from the heated gas,rotating the shaft.
 21. The system according to claim 20 wherein thepredetermined high temperature is between about 1800 and 2100 degreesFahrenheit (F.) and the feed gas has a temperature between about 1200and 1600 degrees Fahrenheit (F.).
 22. The system according to claim 19further comprising the reactor configured for receiving feedstock, thefeedstock comprising at least one of vacuum residue and solventdeasphalter pitch to produce the coke heavy spent catalyst.
 23. Thesystem according to claim 19 wherein the predetermined high pressure isbetween about 150 and 500 psig and the predetermined low pressure isbetween about 30 and 70 psig.
 24. The system according to claim 19wherein the syngas further comprises H₂ and the separator unit isfurther configured to separate at least a portion of the H₂ from thecompressed syngas, the portion of the H₂ being used for another system,reducing overall CO₂ emissions.
 25. The system according to claim 19wherein the reactor is configured for receiving feedstock that reactswith catalyst to produce the coke heavy spent catalyst and the heat foroperating the reactor at reaction temperatures is at least about 600 BTUper pound of feedstock.